Methods for efficiently acquiring wide-azimuth towed streamer seismic data

ABSTRACT

A technique for use in marine seismic surveying includes a method and an apparatus. In one aspect, the method includes towing a seismic spread including a source multiple streamers on a generally curved advancing path, the streamers being actively steered. The source is fired and data is acquired on the curve. In other aspects, the method is performed with only a single vessel or the generally curved advancing path is a sincurve advancing path. The method may include a dual circular shoot in another aspect. And, in yet another aspect, the invention includes an apparatus comprised of a computing apparatus on board a tow vessel receiving positioning data from the marine seismic streamers. It is also programmed to: sail the tow vessel in a generally curved advancing path and actively steer the marine seismic streamers through the generally curved advancing path.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority under 35 U.S.C. §119(e) to U.S. Provisional Application Ser. No. 60/938,547 filed May 17, 2007, entitled, “Methods for Efficiently Acquiring Wide-Azimuth Towed Streamer Seismic Data”, and filed in the name of the inventors Nicolae Moldoveanu and Steven Fealy.

The present application claims priority under 35 U.S.C. §119(e) to U.S. Provisional Application Ser. No. 60/969,203 filed Aug. 31, 2007, entitled, “Methods for Efficiently Acquiring Wide-Azimuth Towed Streamer Seismic Data”, and filed in the name of the inventors Nicolae Moldoveanu and Steven Fealy.

The present application claims priority under 35 U.S.C. §119(e) to U.S. Provisional Application Ser. No. 60/966,534 (converted from U.S. application Ser. No. 11/836,675, filed Aug. 9, 2007, by petition filed Aug. 31, 2007), entitled, “Methods for Efficiently Acquiring Wide-Azimuth Towed Streamer Seismic Data”, and filed in the name of the inventors Nicolae Moldoveanu and Steven Fealy.

The present application claims priority under 35 U.S.C. §120 to U.S. application Ser. No. 11/836,675, filed Aug. 9, 2007, entitled, “Methods for Efficiently Acquiring Wide-Azimuth Towed Streamer Seismic Data”, and filed in the name of the inventors Nicolae Moldoveanu and Steven Fealy, which was converted to U.S. Provisional Application Ser. No. 60/966,534 by petition filed Aug. 31, 2007.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the field of marine seismic data acquisition methods. More particularly, the invention relates to methods for acquiring high quality, towed-array marine seismic surveys.

2. Discussion of Related Art

A marine seismic acquisition survey typically involves one or more vessels towing at least one seismic streamer through a body of water believed to overlie one or more hydrocarbon-bearing formations. As those in the art having the benefit of this disclosure will appreciate, a “marine” survey may be performed not only saltwater environments, but also in fresh and brackish waters. The term “marine” is not limited to saltwater as used in this context by those in the art.

WesternGeco L.L.C. currently conducts high-resolution Q-MARINE™ surveys, in some instances covering many square kilometers. A survey vessel known as a Q-TECHNOLOGY™ vessel may conduct seismic surveys towing multiple 1,000 m-10,000 m cables with a crossline separation of 25 m-50 m, using the WesternGeco proprietary calibrated Q-MARINE™ source. “Q” is the WesternGeco proprietary suite of advanced seismic technologies for enhanced reservoir location, description, and management. For additional information on Q-Marine™, a fully calibrated, point-receiver marine seismic acquisition and processing system, as well as Q-Land™ and Q-Seabed™, see http://www.westerngeco.com/q-technology.

In many areas of the world hydrocarbon reservoirs located in structurally complex areas may not be adequately illuminated even with advanced towed-array acquisition methods. For example, the shallow, structurally complex St. Joseph reservoir off Malaysia produces oil and gas in an area that poses many surveying and imaging challenges. Strong currents, numerous obstructions and infrastructure, combined with difficult near-surface conditions, may hinder conventional survey attempts to image faults, reservoir sands, salt domes, and other geologic features.

To achieve high density surveys in regions having a combination of imaging and logistical challenges, a high trace density and closely spaced streamers may be used. However, this presents the potential of entangling and damaging streamer cables and associated equipment, unless streamer steering devices are closely monitored and controlled. Wide-azimuth towed streamer survey data is typically acquired using multiple vessels, for example: one streamer vessel and two source vessels; two streamer vessels and two source vessels; or one streamer vessel and three source vessels. Many possible marine seismic spreads comprising streamers, streamer vessels, and source vessels may be envisioned for obtaining wide- or rich-azimuth survey data.

Several wide- or rich-azimuth techniques are known to the art. Cole, R. A. et al., “A circular seismic acquisition technique for marine three dimensional surveys”, Offshore Technology Conference, OTC 4864, May 6-9, 1985, Houston, Tex., described a concentric circle shooting scheme for obtaining three dimensional marine survey data around a sub-sea salt dome. Another technique was described by Cole, R. A et al., in the paper presented at the SEG conference in 1988 “Three dimensional marine data acquisition using controlled streamer feathering”, where overlapping circles acquisition is proposed. The concentric circle technique could be useful perhaps when the location of the subsurface feature, like salt dome, is known. The overlapping circles technique could offer an increase in acquisition efficiency versus conventional acquisition.

While the Q suite of advanced technologies for marine seismic data acquisition and processing may provide detailed images desired for many reservoir management decisions, including the ability to acquire wide- and/or rich azimuth data, the ability to acquire higher quality marine seismic data with less cost, or to increase the fold while also increasing the diversity of azimuth and offset, are constant goals of the marine seismic industry and would be viewed as advances in the art.

The present invention is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

SUMMARY OF THE INVENTION

In a first aspect, the present invention includes a method comprising: towing a marine seismic spread including a source and a plurality of marine seismic streamers, the marine seismic streamers including a plurality of acoustic receivers, in a generally curved advancing path over a sub-sea geologic region; actively steering the marine seismic streamers through the generally curved advancing path; shooting the source while towing the marine seismic spread in the generally curved advancing path; and recording reflections from sub-sea geologic features using the receivers during the generally curved advancing path.

In a second aspect, the present invention includes a method, consisting essentially of: sailing a single vessel towing a marine seismic spread including a source and a set of marine seismic streamers, the marine seismic streamers including a plurality of acoustic receivers, in a generally curved advancing path over a sub-sea geologic region; actively steering the marine seismic streamers through the generally curved advancing path; shooting the source while towing the marine seismic spread in the generally curved advancing path; and recording reflections from sub-sea geologic features using the receivers during the generally curved advancing path.

In a third aspect, the invention includes a method comprising: towing a marine seismic spread including a source and a set of marine seismic streamers, the marine seismic streamers including a plurality of acoustic receivers, in a sincurve advancing path over a sub-sea geologic region; and acquiring seismic data while traveling the sincurve advancing path.

In a fourth aspect, the invention includes a method comprising: towing a first marine seismic spread including a first source and a first set of marine seismic streamers, the marine seismic streamers including a plurality of acoustic receivers, in a first circular path over a sub-sea geologic region; and towing a second marine seismic spread including a second source and a second set of marine seismic streamers, the marine seismic streamers including a plurality of acoustic receivers, in a second, non-overlapping circular path over the sub-sea geologic region; and acquiring seismic data while traveling the generally curved advancing path.

In a fifth aspect, the invention includes an apparatus, comprising: a tow vessel; an array of marine seismic streamers; and a computing apparatus on board the tow vessel. Each streamer of the array includes: a seismic cable; a plurality of receivers disposed on the cable along the length thereof; and a plurality of steering devices. The computing device receives positioning data from the marine seismic streamers and is programmed to: sail the tow vessel in a generally curved advancing path over a sub-sea geologic region; and actively steer the marine seismic streamers through the generally curved advancing path.

The above presents a simplified summary of the invention in order to provide a basic understanding of some aspects of the invention. This summary is not an exhaustive overview of the invention. It is not intended to identify key or critical elements of the invention or to delineate the scope of the invention. Its sole purpose is to present some concepts in a simplified form as a prelude to the more detailed description that is discussed later.

BRIEF DESCRIPTION OF THE DRAWINGS

The manner in which the objectives of the invention and other desirable characteristics can be obtained is explained in the following description and attached drawings in which:

FIG. 1 is a plan, overhead schematic view of a first embodiment of the present invention;

FIG. 2 is a computerized rendition of a plan view of the survey area covered by generally circular sail lines of the embodiment of FIG. 1 over time during a shooting and recording survey;

FIG. 3 is a plan, overhead schematic view of a second embodiment of the present invention;

FIG. 4 is a computer rendition illustrating offset and azimuth distribution for a subsurface area of 1000 m×1000 m in accordance with one method of the invention;

FIG. 5 is a print of a computer display screen illustrating fold, offset and azimuth distribution for a certain bin of seismic data obtained using a method of the invention;

FIG. 6-FIG. 9 are plan, overhead schematic views of other, alternative embodiments of the present invention; and

FIG. 10A and FIG. 10B illustrate another embodiment of the present invention, useful in gathering four-dimensional (“4D”), or time lapse, marine seismic data.

FIG. 11 is a plan or overhead schematic view of one embodiment of the invention in which the generally advancing path is a sinusoidal curve, or “sincurve”;

FIG. 12 is a plan view of a sinusoidal curve path symmetrical with the one presented in FIG. 1;

FIG. 13 is another plan view of a combination of two sinusoid curves;

FIG. 14A-FIG. 14B show the sincurves moved in the x direction with DX (FIG. 14A) and in the y-direction with DY (FIG. 14B) to cover the whole survey area;

FIG. 15 is a computer simulation of several sincurves moved in x- and y-directions by DX and DY, respectively, to cover a part of the survey area;

FIG. 16A-FIG. 16B illustrate other possible configurations if another source vessel is added to the streamer vessel for a sincurve acquisition;

FIG. 17 illustrates that the source on the streamer vessel could be equipped with a dual source array, s1 and s2; however the typical source configuration for sincurve shooting geometry is a single source array;

FIG. 18-FIG. 19 illustrate certain advantages of the present invention;

FIG. 20 illustrates the ratio between the real offset versus the nominal offset measured from the source to the receiver;

FIG. 21 graphs the offset-azimuth distribution for a series of bins generated from a sincurve acquisition geometry;

FIG. 22 is a vector offset component diagram for a sincurve acquisition;

FIG. 23 is a plan, overhead schematic views of another embodiment of the invention employing a circular shoot; and

FIG. 24A-FIG. 24B shows a rack mounted computer system such as may be used in some aspects of the present invention.

While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

One or more specific embodiments of the present invention will be described below. It is specifically intended that the present invention not be limited to the embodiments and illustrations contained herein, but include modified forms of those embodiments including portions of the embodiments and combinations of elements of different embodiments as come within the scope of the following claims. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. Nothing in this application is considered critical or essential to the present invention unless explicitly indicated as being “critical” or “essential.”

The present invention will now be described with reference to the attached figures. Various structures, systems and devices are schematically depicted in the drawings for purposes of explanation only and so as to not obscure the present invention with details that are well known to those skilled in the art. Nevertheless, the attached drawings are included to describe and explain illustrative examples of the present invention.

The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended to be implied by consistent usage of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than that understood by skilled artisans, such a special definition will be expressly set forth in the specification in a definitional manner that directly and unequivocally provides the special definition for the term or phrase.

The present invention relates to methods for efficiently acquiring marine seismic data, wherein “efficiency” may be considered as more cost effective in that less seismic resources are used, and provide improved seismic imaging using minimal marine seismic equipment. For example, some embodiments may employ only one vessel, although an additional source vessel may be used in other embodiments as will be explained more fully below. A richer azimuth survey can be acquired with the present invention than what is acquired with techniques employed to date that are based on parallel acquisition geometry concept.

The technique disclosed herein may be particularly adept at acquiring wide- and/or rich azimuth marine seismic data, and acquiring such data while traversing generally curved advancing paths, which may be characterized as coil patterns or paths. When viewed in plan view, certain advancing paths useful in the invention may resemble overlapping circles, as in a flattened coil. The time to shoot a survey may be longer with this technique compared to traditional linear surveys. If the same survey can be acquired with 4 vessel configuration sailing generally parallel the total time required may be shorter. However the total cost is higher for multiple vessel marine seismic data acquisition, and multiple vessels are not always available.

A distinct feature of the inventive methods is that the azimuth is changing from shot to shot. This excludes redundancy in the azimuths acquired. Conventional marine acquisition, in contrast, is based on a parallel acquisition geometry that implies azimuth redundancy. A wider azimuth range can be acquired with conventional parallel geometry by adding extra vessels or by repeating the survey with different cross-line offsets. However both of these options add to the cost of the seismic survey.

Although many configurations of source tow vessel and streamer tow vessel may be employed in accordance with the invention, rich- or wide-azimuth towed streamer marine seismic surveys may be acquired in accordance with the technique disclosed herein using a single streamer vessel towing multiple streamers and a minimum of one source array. In certain embodiments the methods include positioning of streamers and/or sources employing positioning apparatus or systems (for example satellite-based systems), one or more streamer steering devices, one or more source array steering devices, and/or one or more noise attenuation apparatus or systems. One suitable system, known as Q-MARINE™ and discussed further below, includes these features and may be useful in methods of the invention.

Turning now to the drawings, FIG. 1 depicts a first embodiment 10 useful in practicing one method in accordance with the present invention. FIG. 1 depicts the generally curved advancing path or sail lines 2 of a seismic source 6 and streamers 4 generally circular as illustrated by the heavy dark line. In this embodiment both the streamers 4 and the wide- or rich-azimuth source 6 are towed by the same vessel 8, although this is not required. In other words, the streamers 4 generally follow the circular sail line 2 having a radius R, where R may range from about 5,500 m to 7,000 m or more.

The sail line or path 2 is not truly circular, as once the first pass is substantially complete, the spread 10 will move slightly in the y-direction (vertical) value of DY, as illustrated in FIG. 2. The spread may also move in the x-direction (horizontal) by a value DX. Note that “vertical” and “horizontal” are defined relative to the plane of the drawing. This is possible with a source vessel such as that known under the trade designation Q™ and marine seismic data acquisition systems known under the trade designation Q-MARINE™, due at least to the following features: accurate positioning system; streamer steering; and advance noise attenuation capabilities due to single sensor acquisition and fine sampling. Note, however, that other conventional marine seismic spreads and vessels may also be used provided that they can be controlled adequately. One example of marine seismic spread that can be used is the solid streamer.

FIG. 2 is a computerized rendition of a plan view of the survey area covered by the generally circular sail lines of the seismic spread and method of FIG. 1 over time during a shooting and recording survey, where the displacement from circle to circle is DY in the vertical direction and DX in the horizontal direction. In FIG. 2, note that several generally circular sail lines 2 (only one indicated) cover the survey area. In this example, the first generally circular sail line was acquired in the southeast (“SE”) corner of the survey. When a first generally circular sail path 2 is completed the vessel 8 (shown in FIG. 1) moves along the tangent with a certain distance, DY, in vertical direction, and starts a new generally circular path 2. Several generally circular curved paths 2 may be acquired until the survey border is reached in the vertical direction. A new series of generally circular paths 2 may then be acquired in a similar way, but the origin will be moved with DX in the horizontal direction. This way of shooting continues until the survey area is completely covered.

The design parameters for practicing methods within the invention include the radius R of the circle, the radius being a function of the spread width and also of the coverage fold desired; DY, the roll in the y-direction; DX, the roll in the x-direction. DX and DY are functions of streamer spread width and of the coverage fold desired to be acquired. The radius R of the circle may be larger than the radius used during the turns and is a function of the streamer spread width. The radius R may range from about 5 km to about 10 km. The radius R ranges from 6 km to 7 km in one particular embodiment.

The total number of kilometers acquired over a given area depends on the circle radius R and the values DX and DY. The total number of shots acquired with the coil shooting technique disclosed herein increases with increased radius R. DX and DY may range from about 0.5 W to about 2 W, or from about 0.5 W to about W, where W is the streamer spread width. Certain embodiments where DX=DY=W give a continuity of the surface receiver coverage. Certain embodiments wherein DX=DY=0.5 W give a continuity in subsurface midpoint coverage. The values of DX and DY may be the same or different and may each range from about 500 m to about 1200 m or more. The value of DX and DY may be selected based on the survey objectives. For instance for a development type survey DX and DY should be smaller than for an exploration survey. Also, as DX and DY determine the source sampling, processing requirements should be considered when the survey is designed.

The present technique includes methods wherein the streamer tow vessel and other vessels travel clockwise or counterclockwise. There is no intrinsic advantage of one direction over the other, and the clockwise versus counter-clockwise directions may be selected at the beginning of each new swath as a function of the currents. It is generally not practical to change direction from circle to circle (for example clockwise then counter-clockwise) due to loss of time.

FIG. 3 is a plan, overhead schematic view of a second embodiment 20 of the present invention. In this embodiment, a source tow vessel 12 towing a source 6′ following a generally circular advancing path or coil path 2′ is used in conjunction with a streamer tow vessel 8 towing a source 6 and streamers 4 following its own generally circular advancing path or coil path 2. One possible position of source tow vessel 12 is illustrated in FIG. 3 at a radius equal to R−dR.

FIG. 6 illustrates a third embodiment 30, in which towing vessels are not illustrated, comprising a second source 6′ traveling on the same generally circular advancing path 2 as the source 6 associated with the streamer vessel. The source 6′ is positioned behind the streamers 4 at a certain interval or distance I, which is not critical but may range from about 0.5 L to 2.0 L or more where L is the streamer length.

Two possible advantages of methods of various embodiments of the present invention for acquiring rich and/or wide-azimuth towed streamer surveys are illustrated in FIG. 4 and FIG. 5. As illustrated in the computer rendition of FIG. 4, rich azimuth and offset distribution is collected, and very high fold is acquired, as is apparent in FIG. 5, a copy of a computer screen display indicating the results of a method of the present invention.

Another possibility is for a streamer tow vessel and at least one source tow vessel to follow a generally closed curve as illustrated schematically in FIG. 7. The vessels themselves are not shown in FIG. 7, only their generally advancing paths. The streamer tow vessel advances on a general closed curve passing through the following points: A, B, C, D, E, F, G, H, I, J, G, K, E, L, C, M, A. The streamer tow vessel starts at point A and returns to the same point. Once finished with the first path, the spread may move from point A a certain distance DX, in the x-direction, and DY, in the y-direction and a new curve will start as illustrated schematically in FIG. 8. FIG. 8 is an example of two closed curves that are separated by DX and DY distances. The way points of the second path are 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 1.

The closed curve could be generated as a series of tangent circles as illustrated schematically in FIG. 9. In this method, of coil shooting acquisition, the streamer tow vessel traverses ½ of a circle and moves to the next circle (“figure 8” pattern) until the survey limit is reached. Then the vessel will traverse in reverse direction acquiring the other semi-circumferences. The next series of circles will be shifted with DX and DY in x-direction and respectively, y-direction. The extent of closed curve in one direction and the total number of closed curves acquired over an area depend on the survey size.

The methods of the invention may be used in 4D, or time lapse, marine seismic data acquisition. Consider an acquisition shooting pattern such as the one shown in FIG. 10A. The initial survey (or baseline) is acquired with a very “tight” curved shooting pattern (three-dimensional or four-dimensional baseline). This shooting pattern results in wide- or rich-azimuth seismic data. This seismic data is very finely sampled and provides a good baseline exploration survey. The objective of time lapse surveys is to determine the changes that are occurring in the reservoir as a result of hydrocarbon production. Therefore, in certain embodiments there is a need only to acquire enough seismic data to monitor the changes in the reservoir, and not necessarily to use the time lapse seismic to interpret the geology as in an exploration survey.

So, while it is necessary to have repeat coverage, it is not necessary that all the previous acquisition traverses are acquired again. In accordance with this aspect of the invention, subsequent time lapse surveys may be acquired with a looser curved shooting pattern where the coils overlay the previous acquisition track, but are not as numerous. This is shown in FIG. 10B, wherein the dashed curves represent traverses from the baseline survey of FIG. 10A that are not repeated. This allows use of wide- or multi-azimuth acquisition in a cost effective way for 4D or time lapse analysis. The data processing on the time lapse may be repeated in comparison to a subset of the original dataset that matches the new coil pattern that is acquired.

To further an understanding of the present technique and its implementation, a more detailed discussion of the marine seismic spread will now be presented. As mentioned above, the illustrated embodiments employ Q™ and Q-MARINE™ technologies. As used herein, “Q™” is the WesternGeco proprietary suite of advanced seismic technologies for enhanced reservoir location, description, and management. “Q-MARINE™” systems, as discussed herein, refer to the marine seismic spreads employed by WesternGeco and having an accurate positioning system; streamer steering; and advance noise attenuation capabilities.

In general, in the illustrated embodiments, the streamers are steered through their generally curved advancing paths by controlled steering from streamer steering devices. The position of each seismic acoustic receiver is determined during the turns through acoustic networks, which may or may not be full streamer length acoustic networks. This ability to control the motion of the streamers and determine positions of the receivers during turns allows the marine seismic team to gather valuable reservoir and geologic data with increased efficiency.

In the present discussion of the streamer systems, as used herein:

-   -   “wide- and/or rich azimuth seismic survey” means acquiring         marine seismic data through a range of (or all) angles that a         direct line from a source to a receiver makes with true north.         The phrase includes full-azimuth seismic surveys.     -   “cluster” means a plurality (i.e., more than one) of similar         components that are used together.     -   “geophone” means a device for detecting seismic energy in the         form of particle motion during seismic acquisition (land,         marine, or transition zone environments).     -   “hydrophone” means a device for detecting seismic energy in the         form of pressure changes under water during marine seismic         acquisition.     -   “multicomponent” refers to a combination of seismic data sensors         that includes two or more closely-spaced (within a fraction of         the minimal wavelength of interest) seismic sensors such as a         hydrophone, a geophone, an accelerometer, or a pressure gradient         configuration of hydrophones. “4C,” for example, refers to a         particular type of multicomponent seismic data resulting from         the combination of a hydrophone with three orthogonally oriented         geophones or accelerometers.     -   “operatively connected” means directly or indirectly connected         for transmitting or conducting information, force, energy, or         matter.

Many streamers configurations may be useful in the invention, including conventional single component streamers and multicomponent streamers. One set of streamer systems useful in the invention are those described in assignee's published United States patent application number 20060239117 A1, published Oct. 26, 2006, and incorporated below. This published patent application describes streamer systems for acquiring seismic data including a plurality of first cable sections each employing a first sensor configuration therein, and at least one second cable section operatively connected to one or more of the first cable sections and employing a second sensor configuration therein.

In particular embodiments of the streamer system, each of the first cable sections has substantially the same length, and each of the second cable sections has a length substantially less than the length of the first cable sections. The first cable sections may be operatively connected in series to substantially define a single streamer. In such embodiments, the single streamer may include at least one second cable section operatively connected in series with the first cable sections. Accordingly, the one or more second cable sections may be positioned upstream of the first cable sections within the single streamer, or positioned between two of the first cable sections within the single streamer. Alternatively, the single streamer may include at least one second cable section operatively connected in parallel with one or more of the first cable sections. Thus, for example, the single streamer may include three second cable sections connected in parallel with one or more of the first cable sections.

It will be appreciated that in practicing methods of the present invention a plurality of streamers may be operatively connected in parallel to substantially define a streamer array. The streamer array may include at least one second cable section each operatively connected in series with a plurality of the first cable sections within a single streamer. Accordingly, each series-connected second cable section may be positioned upstream of the respective first cable sections within the single streamer, or positioned between two of the first cable sections within the single streamer. Alternatively, such a streamer array may include at least one second cable section each operatively connected in parallel with the streamers. Accordingly, each second cable section may be positioned between two of the streamers, e.g., so as to substantially define a mini-streamer.

Particular embodiments of streamer systems useful in the invention may employ a first sensor configuration adapted for measuring seismic data in an upper part of the frequency band of interest, e.g., having a frequency in the range of approximately 20 Hz to approximately 125 Hz. These embodiments may further employ a second sensor configuration adapted for measuring seismic data in a lower part of the frequency band of interest, e.g., having a frequency in the range of approximately 2 Hz to approximately 20 Hz. It will be appreciated by those skilled in the art that 20 Hz is used as a representative threshold frequency that separates an “upper” frequency portion or band from a “lower” frequency portion or band. Accordingly, the phrase “approximately 20 Hz” means 20 Hz±an appropriate margin (e.g., 10 Hz).

In other particular embodiments of streamer systems useful in the invention, the first sensor configuration may include a conventional hydrophone distribution, and the second sensor configuration may include one or more multicomponent sensors. More particularly, the first sensor configuration may include a plurality of hydrophones distributed longitudinally along each first cable section. Thus, the first sensor configuration may include longitudinally spaced hydrophones, or it may include longitudinally-spaced hydrophone clusters.

In particular embodiments wherein the first sensor configuration employs hydrophone clusters, the hydrophone clusters may be arranged to define a pressure gradient configuration. The hydrophone clusters may have a longitudinal spacing from one another not exceeding approximately 3.125 m. The hydrophone clusters may each include at least two transversely-spaced hydrophones. Accordingly, each hydrophone cluster may include three or more hydrophones having a relatively short transverse spacing, e.g., a transverse spacing from one another not exceeding approximately 4-10 cm. Alternatively, the first sensor configuration may include a plurality of hydrophones distributed longitudinally according to a first separation distance, and the second sensor configuration may include a plurality of hydrophones distributed longitudinally according to a second separation distance that is substantially different from the first separation distance. Thus, e.g., the first separation distance may be approximately 3.125 m, 6.25 m, or 12.5 m. The second separation distance may lie in a range of approximately 1.5 m to approximately 3 m.

In other useful embodiments of streamer systems useful in the invention, the first sensor configuration may include one or more particle motion sensors therein, such as a particle velocity sensor, a pressure gradient sensor, an accelerometer, or a combination of these. In yet other particular embodiments of streamer systems useful in the invention, the second sensor configuration may include one or more particle motion sensors therein. Thus, the particle motion sensors may include at least one of a particle velocity sensor, a pressure gradient sensor, an accelerometer, and a combination thereof. Alternatively, the second sensor configuration may include one or more hydrophones. Thus, e.g., the second sensor configuration may include a plurality of longitudinally-spaced hydrophone clusters. In particular embodiments, these clusters may be spaced apart by a separation distance in the range of approximately 1.5 m to approximately 3 m.

The sources used to implement various embodiments of the present invention may be practically any seismic source known to this art. The source may be a conventional impulse type source, such as an airgun, or a conventional sweep source. As mentioned above, one embodiment employs the Q™ and Q-MARINE™ technologies which, as mentioned above, includes the calibrated Q-MARINE™ source. However, the invention is not so limited.

To further an understanding of the technique disclosed herein, a discussion of controlling and positioning elements of the marine seismic spread will now be presented. In the following discussion regarding controlling the spread and positioning the various elements thereof, the term or phrase:

-   -   “without the need for the spread to repeat a path once         traversed” means that methods and systems of the invention do         not require a marine seismic spread to repeat a particular path         to obtain wide- and/or rich azimuth seismic survey data.     -   “spread” and the phrase “seismic spread” are used         interchangeably herein and mean the total number of components,         including vessels, vehicles, and towed objects including cables,         sources and receivers, that are used together to conduct a         marine seismic data acquisition survey.     -   “position”, when used as a noun, is broader than “depth” or         lateral (horizontal) movement alone, and is intended to be         synonymous with “spatial relation.” Thus “vertical position”         includes depth, but also distance from the seabed or distance         above or below a submerged or semi-submerged object, or an         object having portions submerged. When used as a verb,         “position” means cause to be in a desired place, state, or         spatial relation. The term may also include orientation, such as         rotational orientation, pitch, yaw, and the like.     -   “control”, used as a transitive verb, means to verify or         regulate by comparing with a standard or desired value. Control         may be closed loop, feedback, feed-forward, cascade, model         predictive, adaptive, heuristic, and combinations thereof.     -   “controller” means a device at least capable of accepting input         from sensors and meters in real time or near-real time, and         sending commands directly to a vessel steering sub-system, and         optionally to spread control elements, and/or to local devices         associated with spread control elements able to accept commands.         A controller may also be capable of accepting input from human         operators; accessing databases, such as relational databases;         sending data to and accessing data in databases, data warehouses         or data marts; and sending information to and accepting input         from a display device readable by a human. A controller may also         interface with or have integrated therewith one or more software         application modules, and may supervise interaction between         databases and one or more software application modules.     -   “PID controller” means a controller using proportional,         integral, and derivative features, as further explained herein.         In some cases the derivative mode may not be used or its         influence reduced significantly so that the controller may be         deemed a PI controller. It will also be recognized by those of         skill in the control art that there are existing variations of         PI and PID controllers, depending on how the discretization is         performed. These known and foreseeable variations of PI, PID and         other controllers are considered useful in practicing the         methods and systems of the invention.     -   “spread control element” means a spread component that is         controllable and is capable of causing a spread component to         change coordinates, either vertically, horizontally, or both,         and may or may not be remotely controlled.     -   “control position”, “position controllable”, “remotely         controlling position” and “steering” are generally used         interchangeably herein, although it will be recognized by those         of skill in the art that “steering” usually refers to following         a defined path, while “control position”, “position         controllable”, and “remotely controlling position” could mean         steering, but also could mean merely maintaining position. In         the context of the invention, “control position” means we use at         least a tracking point position and compare it to a pre-plot         path in order to give steering commands to vessel steering         elements.     -   “Real-time” means dataflow that occurs without any delay added         beyond the minimum required for generation of the dataflow         components. It implies that there is no major gap between the         storage of information in the dataflow and the retrieval of that         information. There may be a further requirement that the         dataflow components are generated sufficiently rapidly to allow         control decisions using them to be made sufficiently early to be         effective.     -   “Near-real-time” means dataflow that has been delayed in some         way, such as to allow the calculation of results using         symmetrical filters. Typically, decisions made with this type of         dataflow are for the enhancement of real-time decisions. Both         real-time and near-real-time dataflows are used immediately         after the next process in the decision line receives them.     -   phrase “vessel steering sub-system” means any device or         collection of components that are capable of generating commands         to vessel steering elements, such as rudders, thrusters, and the         like, to accomplish the intended movements of the seismic towing         vessel. In some embodiments the vessel steering sub-system may         include a vessel tracking computer and/or an autopilot. In other         embodiments a vessel steering sub-system may bypass conventional         tracking and autopilot functions, and may be simply a vessel         rudder controller, and/or a vessel thruster controller (these         embodiments may be referred to as “steering the vessel directly”         using the controller). In yet other embodiments, all of these         components (tracking computer, autopilot, rudder controller, and         thruster controllers) may be employed.

The methods disclosed herein may be used in conjunction with conventional spread control devices. These devices include source steering devices and streamer steering devices. Such devices are often part of the spread and towed by the vessel. For example, a source reference point generally must be within 10 m cross line of the target in order for a source steering device with an ability to move the source 10 m crossline to move the source reference closer to the target.

Methods of the invention may incorporate one of the so-called Advance Spread Control systems and methods described in assignee's co-pending U.S. patent application Ser. No. 11/122,646, filed Mar. 5, 2005, (published patent application no. 20060256653, published Nov. 16, 2006), incorporated below. In these systems and methods, a marine seismic spread includes a vessel-mounted acoustic Doppler current meter to measure at least a horizontal component of a current velocity vector at least at one location generally ahead of the seismic spread elements, and a controller adapted to use at least the horizontal component of the measured current velocity vector to control position of a seismic spread element. The controller may control position either before the spread element encounters the measured current ahead of the vessel, or when the spread element passes by the point or location where the current was measured.

The described systems may include a seismic spread comprising one or more vessels such as towing vessels, a chase vessel, a work vessel, one or more a seismic sources, and one or more seismic streamers towed by towing vessels. The streamers and sources may be separately towed or towed by the same vessel, and the acoustic Doppler current meter may be mounted on a chase vessel, a work vessel, an automated underwater vehicle (“AUV”), or a tow vessel, as long as it is able to provide the desired data, and may comprise a transducer that produces at least one beam that is horizontal and forward looking, or has a useable forward-looking horizontal component, and may be adapted to measure a current velocity vector at a point ahead of the towing vessel. The controller may control position of all or some of the spread elements through commands given to spread control elements, such as deflectors, steerable birds, and the like. Optionally, the vessel-mounted acoustic Doppler current meter may be motion-compensated.

Controllers useful in the systems and methods of the invention may vary in their details. One PID controller useful in the invention may be expressed mathematically as: u(t)=K _(p) [e(t)+1/T _(i) ·∫e(t)dt+T _(d) ·è(t)]  (1) wherein:

-   -   ∫≡integrate;     -   è(t)≡the time derivative;     -   u(t)≡controller output, either meters across to a tracking         control device such as that known under the trade designation         Robtrack/STS500, or heading to an autopilot;     -   e(t)≡difference between wanted (planned, reference) and measured         (current position, y) value;     -   T_(d)≡a constant for describing the derivative part of the         algorithm (the derivative part may be filtered to avoid deriving         high frequencies);     -   T_(i)≡a constant for describing the integrating part of the         algorithm; and     -   K_(p)≡a proportional gain constant.

In the s-plane (Laplace), the PID controller may be expressed as: H _(r)(s)=K _(p)[1+1/T _(i) s+T _(d) s/(1+T _(f) s)]  (2) wherein:

-   -   s≡the variable in the s-plane; and     -   T_(f)≡a constant describing the filtering part of the derivative         part of the algorithm.

For discretization, a variety of transforms may be employed, and some constants may or may not be useful. For example, the T_(f) constant may not be necessary in some instances, but may be especially useful in other scenarios. As one discretization example, the z-transform may be used, meaning that the integral part of the algorithm may be approximated by using a trapezoid model of the form: s=(1−z ⁻¹)/T  (3) while the derivative part may be approximated using an Euler model: s=2/T·(1−z ⁻¹)/(1+z ⁻¹)  (4) wherein T is the sampling time. The resulting discrete model may then be used directly in the steering algorithm. Other discrete models, derived using other transforms, are useful in the invention, and will be apparent to control technicians or control engineers of ordinary skill.

Model Predictive Control (“MPC”) is an advanced multivariable control method for use in multiple input/multiple output (“MIMO”) systems. An overview of industrial Model Predictive Control can be found at: www.che.utexas.edu/˜qin/cpcv/cpcv14.html. MPC computes a sequence of manipulated variable adjustments in order to optimize the future behavior of the process in question. At each control time k, MPC solves a dynamic optimization problem using a model of the controlled system, so as to optimize future behavior (at time k+1, k+2 . . . k+n) over a prediction horizon n. This is again performed at time k+1, k+2 . . . . MPC may use any derived objective function, such as Quadratic Performance Objective, and the like, including weighting functions of manipulated variables and measurements.

Dynamics of the process and/or system to be controlled are described in an explicit model of the process and/or system, which may be obtained for example by mathematical modeling, or estimated from test data of the real process and/or system. Some techniques to determine some of the dynamics of the system and/or process to be controlled include step response models, impulse response models, and other linear or non-linear models. Often an accurate model is not necessary. Input and output constraints may be included in the problem formulation so that future constraint violations are anticipated and prevented, such as hard constraints, soft constraints, set point constraints, funnel constraints, return on capital constraints, and the like.

It may be difficult to explicitly state stability of an MPC control scheme, and in certain embodiments of the present invention it may be necessary to use nonlinear MPC. In so-called advance spread control of marine seismic spreads, PID control may be used on strong mono-variable loops with few or non-problematic interactions, while one or more networks of MPC might be used, or other multivariable control structures, for strong interconnected loops. Furthermore, computing time considerations may be a limiting factor. Some embodiments may employ nonlinear MPC.

Feed forward algorithms, if used, will in the most general sense be task specific, meaning that they will be specially designed to the task they are designed to solve. This specific design might be difficult to design, but a lot is gained by using a more general algorithm, such as a first or second order filter with a given gain and time constants.

The introduction of a tracking point may serve at least two purposes. First, it gives a more flexible solution for a track that we want parts of the spread to follow. Second, if other means are used for controlling source positions, like a winch or a source deflector, the vessel will in many occasions have “spare” steering capacity available. This may mean that by moving the tracking point aft of the sources, streamer front ends and consequentially also the receivers may be closer to where they should be, which may help the streamer steering devices, such as those known under the trade designation Q-FIN, available from WesternGeco, L.L.C., in achieving their steering objectives.

In certain embodiments, a tracking point will not be a static point in the spread, as time varying currents may result in the center of source steering objective and the tracking point steering objective unable to be met at the same time. In these embodiments, the tracking point may be moved, either dynamically or non-dynamically, until both objectives can be met with a certain slack. The reverse might also be the case, i.e., having excess steering power resulting in moving the tracking point further aft. If the movement of the tracking point is above a predefined distance, a new set of parameters for both the controller and the feed forward controller may be used to optimize the controller performance.

The control systems and methods discussed herein may be used in the spread embodiments disclosed herein as well as other spread configurations. For example, for obtaining deghosted seismic data, it may be possible to provide one or more seismic streamers with a companion seismic streamer where the companions are towed in over/under fashion. The vertical distance between seismic streamers in an over/under seismic streamer pair may range from 1 m to 50 m or more. In one particular embodiment, the vertical distance may be about 5 m. A selected number of hydrophones, either mounted within the seismic streamer or in/on equipment mounted onto the seismic streamer, may be used as receivers in an acoustic ranging system and thereby provide knowledge of the horizontal and vertical position of seismic streamers.

In order to acquire towed streamer marine seismic data during a generally curved advancing path or coil path, the position of acoustic receivers, streamer steering, and noise attenuation are important factors. The streamer tow vessel and streamers may be part of a system known under the trade designation Q-MARINE™, from WesternGeco. In these systems, streamers may be equipped with acoustic transmitters and point receivers for accurate position determination, employing intrinsic ranging modulated acoustics, as taught in U.S. Pat. No. 5,668,775 (“the '775 patent”), incorporated below.

As taught in the '775 patent, the streamer transmitters and point receivers may form a full-streamer-length acoustic network, wherein a unique spread spectrum code of acoustic frequencies are emitted by each of a plurality of acoustic transmitters placed within the streamers, all frequencies being within the seismic frequencies detected by the same receivers during shooting and recording, and the point receivers within the streamers are able to distinguish each transmitter's unique code. Thus, accurate positioning of seismic receivers is possible. Conventional streamers use arrays of hydrophones, such as 12 or 18 hydrophones per group, which are summed together in analog fashion and than recorded.

Systems known Q-MARINE™ use single sensors or point receivers: these are placed in the streamer at intervals, for example one every 3 m to 4 m, and recorded. All point receivers route data to a computer, where digital filters are applied taking advantage of the very fine sampling of the receivers for very powerful coherent noise attenuation of line swell noise and/or streamer cable noise. During the turns the noise from marine current may be stronger, since at least portions of the streamers may be traveling cross-current. This is one reason shooting during turns is not possible with conventional streamers. With systems known as Q-MARINE™, noise can be attenuated from each point receiver very well. Furthermore, streamers may be steered into desired positions by steering devices, as further described herein.

Shooting and recording in the generally curved advancing paths is made possible through the combination of steering of streamers and acoustic positioning networks, and optionally noise attenuation if necessary through digital filtering signals from point receivers in the streamers. Furthermore, the ability to acquire towed streamer marine seismic data during the coiled paths increases data quality by providing richer azimuth data.

Methods of the invention may employ any number of spread control elements, which may include one or more orientation members, a device capable of movements that may result in any one or multiple straight line or curved path movements of a spread element in three dimensions, such as lateral, vertical up, vertical down, horizontal, and combinations thereof. The terms and phrases “bird”, “cable controller”, “streamer control device”, and like terms and phrases are used interchangeably herein and refer to orientation members having one or more control surfaces attached thereto or a part thereof.

A “steerable front-end deflector” (or simply “deflector”) such as typically positioned at the front end of selected streamers, and other deflecting members, such as those that may be employed at the front end of seismic sources or source arrays, may function as orientation members in some embodiments, although they are primarily used to pull streamers and steer sources laterally with respect to direction of movement of a tow vessel. Horizontal separation between individual streamers may range from 10 to about 200 meters. The horizontal streamer separation may be consistent between one streamer and its nearest neighboring streamers. Horizontal and/or vertical control of streamers may be provided by orientation members (not illustrated) which may be of any type as explained herein, such as small hydrofoils or steerable birds that can provide forces in the vertical and/or horizontal planes.

One suitable orientation member is the device known under the trade designation Q-FIN™, available from WesternGeco L.L.C., and described in U.S. Pat. No. 6,671,223, describing a steerable bird that is designed to be electrically and mechanically connected in series with a streamer; another suitable device is that known under the trade designation DIGIBIRD™, available from Input/Output, Inc., Stafford, Tex. Other streamer positioning devices, such as the devices described in U.S. Pat. No. 3,774,570; U.S. Pat. No. 3,560,912; U.S. Pat. No. 5,443,027; U.S. Pat. No. 3,605,674; U.S. Pat. No. 4,404,664; U.S. Pat. No. 6,525,992 and EP Patent Publication No. EP 0613025, may be employed.

Systems used in practicing methods of the invention may communicate with the outside world, for example another vessel or vehicle, a satellite, a hand-held device, a land-based device, and the like. The way this may be accomplished varies in accordance with the amount of energy the system requires and the amount of energy the system is able to store locally in terms of batteries, fuel cells, and the like. Batteries, fuel cells, and the like may be employed, and wireless communication may be sufficient. Alternatively, or in addition, there may be a hard-wire power connection and a hard wire communications connection to another device, this other device able to communicate via wireless transmission.

Certain methods of the invention may work in feed-forwarded fashion with existing control apparatus and methods to position not only the tow vessels, but seismic sources and streamers. Sources and streamers may be actively controlled by using GPS data or other position detector sensing the position of the streamer (e.g., underwater acoustic network), or other means may sense the orientation of one or more individual streamers (e.g. compass) and feed this data to navigation and control systems. While gross positioning and local movement of one or more tracking points, centers of sources and/or a streamer front end center may be controlled via controlling one or more tow vessels, fine control may be accomplished on some other vessel, locally, or indeed a remote location.

By using a communication system, either hardwired or wireless, environmental information ahead of the vessel may be sent to one or more local controllers, as well as the controller for each vessel. The local controllers may in turn be operatively connected to spread control elements comprising motors or other motive power means, and actuators and couplers connected to the orientation members (flaps), and, if present, steerable birds, which function to move the spread components as desired. This in turn adjusts the position of the spread element, causing it to move as desired. Feedback control may be achieved using local sensors positioned as appropriate depending on the specific embodiment used, which may inform the local and remote controllers of the position of one or more orientation members, distance between streamers, a position of an actuator, the status of a motor or hydraulic cylinder, the status of a steerable bird, and the like. A computer or human operator can thus access information and control the entire positioning effort, and thus obtain much better control over the seismic data acquisition process.

In accordance with the present invention, methods are described for acquiring marine seismic data that may be more cost effective and provide improved seismic imaging compared to presently employed methods. Methods of the invention comprise acquiring wide- or rich-azimuth data (as defined herein to include full azimuth data) using a streamer vessel (for example, a single streamer vessel, such as a Q-TECHNOLOGY™ streamer vessel) towing multiple streamer cables using one or more calibrated marine seismic sources (in certain embodiments Q-MARINE™ sources), wherein the streamer vessel and the one or more source arrays traverse a generally curved advancing shooting pattern. In certain embodiments one or more source arrays may traverse a smaller or larger curved pattern than the streamer vessel.

As used herein the phrase “generally curved advancing path” means that the vessels and streamers travel generally in a curve, and there is an advancement in one or more of the x- and y-directions, as explained further herein. The path may be expressed as a coil. The curve may be circular, ovoid (including one or more ovals), elliptical (including one or more ellipses), figure 8, sinusoidal, or other curved path. The path may vary within the same survey; for example, a first portion of the survey may follow an ovoid path, a second portion of the survey may follow an elliptical path, as one of many examples. In addition, as explained in referenced to FIG. 10A and FIG. 10B for time lapse seismic, the subsequent paths may be different from the first or “baseline” path.

As used herein the phrase “tow vessel” includes both streamer tow vessels and source tow vessels; a “streamer tow vessel” means a vessel towing one or more seismic streamer cables, with or without one or more seismic sources; and “source tow vessel” means a vessel towing at least one seismic source, with or without one or more streamers.

Methods of the invention include those wherein there is more than one streamer in the spread, and the distance between streamers is substantially maintained by a plurality of actively controlled streamer steering devices, such as those known under the trade designation Q-FIN™, available from WesternGeco L.L.C., although the invention is not limited to this particular type of streamer steering device.

Combinations of the methods of the invention may be practiced, wherein shooting and recording during the generally curved advancing pattern is performed along with positioning the source and streamer(s) to acquire a wide- and/or rich azimuth seismic survey without the need for the spread to repeat a path once traversed.

Methods of the invention include those wherein split-spread seismic data is acquired by acquiring seismic data simultaneously on one or more seismic source lines, including embodiments wherein the deploying of one or more tow vessels comprises deploying a streamer tow vessel, and methods including deploying one or more source tow vessels starboard of the streamers and one or more source tow vessels positioned port of the streamers, wherein the starboard and port distances are either the same or different, and all vessels traverse their own generally curved advancing paths. In certain methods, the generally curved advancing paths are generally circular and differ in radius by known, controlled amounts. In certain other methods, the generally curved advancing paths are generally sinusoid curves, the shape of the curves being controlled by the design parameters.

Other methods of the invention comprise collecting split-spread marine seismic data, comprising deploying a streamer tow vessel towing a plurality of streamers in a generally curved advancing path over a sub-sea geologic region, and deploying all of the source tow vessels on the starboard (or port) side of one or more streamer tow members to acquire wide- and/or rich azimuth seismic survey data. Certain of these method embodiments may comprise deploying two or more source tow vessels port of (or starboard of) and positioned ahead of the streamers, and deploying two more source tow vessels port of (or starboard of) and positioned behind the streamers. A variation of these embodiments is deploying two or more sources utilizing the same source tow vessels.

Other methods of the invention comprise controlling the one or more source tow vessels and/or streamer tow vessels with one or more controllers alone or in conjunction with other controllers. Certain methods of the invention may comprise towing one or more streamer tow vessels wherein the streamers are towed in configuration selected from side-by-side configuration, over/under configuration, “V” configuration, “W” configuration, or some other configuration.

Methods of the invention may employ multiple, in certain embodiments from 4 to 12 streamer cables, wherein the streamers may be from 1000 m to about 5 km in length, with a separation between streamers ranging from about 25 to about 50 m. Methods of the invention include those which employ so-called “split-spread” systems. These embodiments would comprise passive and/or active deflecting members, such as deflectors known in the art as MONOWING™, available from WesternGeco L.L.C., and other deflectors, such as door-type deflectors.

Methods of the invention for acquiring rich- or wide-azimuth marine seismic data may comprise one or more receiver positioning apparatus or systems, source positioning apparatus or systems, one or more streamer steering devices, one or more source array steering devices, and/or noise attenuation apparatus or systems. Systems known as Q-MARINE™ include these features and may be useful in methods of the invention. Further, all methods of the invention may utilize sequential source shooting or, alternatively, two or more sources may be shot simultaneously, with the sources being encoded so that they may be distinguished during data interpretation. For the same nominal shot point interval, firing two or more sources simultaneously may reduce the shot time interval on each source line compared with sequential shooting.

Methods of the invention may benefit from one or more controllers that control position of one or more tracking points. Tracking points may be anywhere in the marine seismic spread, for example but not limited to the center of a source, a streamer front end center, a streamer back end center, a tracking point somewhere between a center of source and a streamer front end center, a center of a plurality of streamers, a front of any one streamer, and the like. Tracking points may be dynamically or non-dynamically moved within a spread to optimize a given steering strategy, particularly during data acquisition during traversal of the generally curved advancing (coil-like) paths discussed herein. Controllers may be physically a part of the vessel steering sub-system or located separately from the steering sub-system, and may use some or all available information, including, but not limited to, source and vessel positions, vessel gyroscope reading, vessel compass reading, vessel speed log, streamer front end positions (if streamers are present), and historical, real-time, and future current and wind information and predictions when calculating the residual difference, and thus these may be taken into consideration in the calculation of optimum vessel steering path by the vessel steering sub-system.

The phrase “vessel steering sub-system” is defined herein and may differ among the various embodiments of the invention, as explained in the definition. Controllers may be selected from PI controllers, PID controllers (including any known or reasonably foreseeable variations of these), and compute a residual equal to a difference between a tracking point three-dimensional (“3D”) coordinate position and a pre-plot track, optionally together with current and wind measurements, to produce a set point input to a vessel steering algorithm used by a vessel steering sub-system. Controllers may compute the residual continuously or non-continuously. Other possible implementations of the invention are those wherein one or more controllers comprise more specialized control strategies, such as strategies selected from feed forward, cascade control, internal feedback loops, model predictive control, neural networks, and Kalman filtering techniques. Systems and methods of the invention may be used during seismic data collection, including 3D and 4D seismic surveying.

Methods of the invention may include use of seismic spreads comprising one or more other vessels such as chase vessels, work vessels, and the like. The streamers and sources may be separately towed or towed by the same vessel. If towed by separate vessels, two controllers may be employed and two residuals computed. In general, the controller may compute the residual based on what the position measurement system reports as the 3D coordinate position of the tracking point. Although there may be some degree of error in the reported 3D coordinate position due to a variety of error sources, including instrument measurement error, even with the errors the tracking point may be better controlled by steering the vessel the majority of the time.

Methods of the invention may optionally be used in conjunction with other systems and methods. For example, if the centers of each of the sources are tracking points, their 3D coordinate positions may be determined from acoustic ranging networks, GPS, and other position sensors, and since the seismic team knows the paths each tracking point is supposed to follow based on the survey specifications, the controllers may use at least that information to calculate residuals, and a series of set points based on the residuals, for the steering algorithms of each vessel, either to steer the vessels back to the survey-specified paths, or ensure that the survey-specified paths are adhered to.

A full- or wide-azimuth towed streamer survey may also be acquired in accordance with the present invention using a single streamer vessel comprising multiple streamers and a minimum of one source array. In certain embodiments the methods include positioning of streamers and/or sources employing positioning apparatus or systems (for example satellite-based systems), one or more streamer steering devices, one or more source array steering devices, and/or one or more noise attenuation apparatus or systems.

FIG. 11 represents a sinusoidal curved path 1100 that is followed by the streamer vessel (not shown); T and A are parameters that control the shape of the curve. The extent of the curve, L, as well as T and A parameters are survey design parameters. A first marine seismic spread embodiment 10 useful in practicing one method in accordance with the invention is illustrated schematically, with the generally curved advancing path or sail lines of a seismic source 6 and streamers 4 generally sincurve as illustrated by the heavy dark line. In this embodiment both streamers 4 and source 6 are towed by the same vessel (not illustrated). In other words, streamers 4 generally follow the sincurve sail line having the amplitude A and the period T.

The sincurve parameters A and T are determined based on the survey size, shot density we want to achieve and the effect of the noise on the seismic data. If T=2A the sincurve corresponds to a series of tangent semi-circles. The length of the sincurve L is typically less or equal with the survey dimension (length or width). The minimum value of L is equal 2T. If the streamer finished the path along the sincurve it may continue smoothly in a symmetric sincurve that is illustrated in FIG. 12.

The forward and reverse paths along two symmetrical sincurves are illustrated in FIG. 13. The solid sinusoid path is followed by the streamer vessels in one direction and the symmetric dashed sinusoid path is followed by the streamer vessel in the opposite direction. The way points are: 1,2,3,4,5,6,7,8,9 (forward direction) and 10,11,12,13,14,15 16,17,18 (reverse direction).

The spread may also move in the x-direction (horizontal) by a value DX. This is possible with a source vessel such as that known under the trade designation Q™ and marine seismic data acquisition systems known under the trade designation Q-Marine™, due at least to the following features: accurate positioning system; streamer steering; and advance noise attenuation capabilities due to single sensor acquisition and fine sampling.

FIG. 14A-FIG. 14B are computerized renditions of plan views of the survey area covered by the generally sincurve sail lines of the seismic spread and method of FIG. 11 over time during a shooting and recording survey, where the displacement from sincurve to sincurve is DY in the vertical direction and DX in the horizontal direction. In FIG. 15, note that several sincurves cover the survey area. The starting point of the sincurves versus survey boundary is a design parameter that controls the shot density over the survey area. In this example the first sincurve sail line was acquired in the SE corner of the survey. When a first sincurve sail path is completed the vessel moves with a certain distance, DY, in vertical direction, and starts a new sincurve advancing path. Several sincurve advancing paths may be acquired until the survey border is reached in the vertical direction. A new series of sincurve advancing paths may then be acquired in a similar way, but the origin will be moved with DX in the horizontal direction. This way of shooting continues until the survey area is completely covered.

The design parameters for practicing methods within the invention include the sincurve parameters, A, T and L, DY, the roll in the y-direction; DX, the roll in the x-direction and the starting point of sincurves. DX and DY are functions of streamer spread width and of the coverage fold desired to be acquired. The amplitude A of the sincurve may be larger than the radius used during the turns and is a function of the streamer spread width. The amplitude A may range from about 5 km to about 10 km, and may range from 6 km to 7 km. The period T of the sincurve may range from 10 km to about 25 km. The extent of the sincurve, L, has a minimum value of 2T, and a maximum value equal with the survey length or survey width and it may range from 20 km to 30 km.

The total number of kilometers acquired over a given area depends on the amplitude A, period T, sincurve length L and the values DX and DY. The total number of shots acquired with the sincurve shooting methods of the invention increases with larger values for A and T parameters. DX and DY may range from about 0.5 W to about 2 W, or from about 0.5 W to about W, where W is the streamer spread width. Certain embodiments where DX=DY=W give a continuity of the surface receiver coverage. Certain embodiments wherein DX=DY=0.5 W give a continuity in subsurface midpoint coverage. The values of DX and DY may be the same or different and may each range from about 500 m to about 1200 m or more.

Methods of invention include those where a single streamer tow vessel travels along a sincurve, clockwise and counterclockwise. This could be an advantage in an area with localized strong marine currents.

FIG. 16A is a plan or overhead schematic view of another embodiment of the invention. In this method, a source-only vessel S2 towing a source following a sincurve is used in conjunction with a source-streamer vessel S1 towing a source 6 and streamers 4 following its own sincurve. The source vessel S2 travels parallel to the streamer vessel following the same sincurve advancing path. One possible position of source vessel 12 is illustrated in FIG. 13 at a distance dh. The distance dh is determined by design.

FIG. 16B illustrates another embodiment, comprising a second source S2 traveling on the same sincurve as the source S1 associated with the streamer vessel. The source S2 is positioned behind streamers 4 at a certain interval or distance L, which is not critical but may range from about 0.5 L to 2.0 L or more where L is the streamer length and is determined by design.

Another possible embodiment consists in using a dual source array S1 and S2 on the streamer vessels and this is illustrated in FIG. 17. However, the typical source configuration for sincurve acquisition is to use a single source array.

Two of the above-listed possible advantages of methods of the invention for acquiring full and/or wide-azimuth towed streamer surveys are illustrated in FIG. 18 and FIG. 19. FIG. 18 is a computer rendition illustrating offset and azimuth distribution for a subsurface area of 500 m×500 m in accordance with one method of the invention. The azimuth-offset distribution is represented by the vector offset component diagram. It can be noticed that for all azimuths the offset distribution is similar: the inline offsets (horizontal axis) and the crossline offsets (vertical axis) have the same range; the gray colors represent the azimuths. FIG. 19 is a print of a computer display screen illustrating fold, offset and azimuth distribution for a series of bins generated from a sincurve acquisition geometry; it can be noticed that the azimuths from 0° to 360° (full azimuth distribution) are recorded with the same offset range.

As illustrated in the computer rendition of FIG. 18, full azimuth and offset distribution is collected, and very high fold is acquired, as is apparent in FIG. 19, a copy of a computer screen display using a method of the present invention. FIG. 21 graphs the offset-azimuth distribution for a series of bins generated from a sincurve acquisition geometry. FIG. 22 is a vector offset component diagram for a sincurve acquisition.

FIG. 23 illustrates an efficient method to acquire wide-azimuth surveys using coil shooting and simultaneous sources. Vessel 8 and vessel 8′ shoot a circular geometry over the same prospect (not shown). The vessels 8, 8′ are separated by an optimum distance d that could be, for example, 20 to 30 km. Vessel 8 shoots always every N seconds and vessel 8′ shoots at N+/−dt. It is noted that the value of dt can be determined based on the processing requirements. Different mathematical algorithms could be used to optimally derive the shooting sequence. The total acquisition time can be reduced by 50% relative to conventional marine surveys.

As noted above, and as will be appreciated by those in the art having the benefit of this disclosure, the survey vessels 8, 8′ will be equipped with computer-implemented navigation and control systems. FIG. 24A-FIG. 24B depict a rack-mounted computing apparatus 2400 with which the navigation and control systems may be implemented. The computing apparatus 2400 includes a processor 2405 communicating with some storage 2410 over a bus system 2415. The storage 2410 may include a hard disk and/or random access memory (“RAM”) and/or removable storage such as a floppy magnetic disk 2417 and an optical disk 2420. The storage 2410 is encoded with a data structure 2425 storing the data set acquired as discussed above, an operating system 2430, user interface software 2435, and an application 2465.

The user interface software 2435, in conjunction with a display 2440, implements a user interface 2445. The user interface 2445 may include peripheral I/O devices such as a key pad or keyboard 2450, a mouse 2455, or a joystick 2460.

The processor 2405 runs under the control of the operating system 2430, which may be practically any operating system known to the art. The application 2465 is invoked by the operating system 2430 upon power up, reset, or both, depending on the implementation of the operating system 2430. The application 2465 issues navigation commands (“NAV”) to the vessel 8, 8′ in accordance with its program to sail the vessel 8, 8′ on the generally advancing curved path 2 and to tow the marine seismic streamers 4 and/or source 6, depending on the particular embodiment. The application 2465 also, in this particular embodiment, receives positioning data (“POSITION”) from the marine seismic streamers 4 and issues steering commands (“STEERING”) to the steering devices thereon.

Note that the nature of the software control in terms of architecture or situs is material to the practice of the invention. For example, in some embodiments, the navigation and streamer steering may be performed by separate software components that may be, for instance, utilities or daemons. Similarly, this functionality may be distributed across separate computing apparatuses in some embodiments, as well.

Some portions of the detailed descriptions herein are consequently presented in terms of a software implemented process involving symbolic representations of operations on data bits within a memory in a computing system or a computing device. These descriptions and representations are the means used by those in the art to most effectively convey the substance of their work to others skilled in the art. The process and operation require physical manipulations of physical quantities. Usually, though not necessarily, these quantities take the form of electrical, magnetic, or optical signals capable of being stored, transferred, combined, compared, and otherwise manipulated. It has proven convenient at times, principally for reasons of common usage, to refer to these signals as bits, values, elements, symbols, characters, terms, numbers, or the like.

It should be borne in mind, however, that all of these and similar terms are to be associated with the appropriate physical quantities and are merely convenient labels applied to these quantities. Unless specifically stated or otherwise as may be apparent, throughout the present disclosure, these descriptions refer to the action and processes of an electronic device, that manipulates and transforms data represented as physical (electronic, magnetic, or optical) quantities within some electronic device's storage into other data similarly represented as physical quantities within the storage, or in transmission or display devices. Exemplary of the terms denoting such a description are, without limitation, the terms “processing,” “computing,” “calculating,” “determining,” “displaying,” and the like.

Note also that the software implemented aspects of the invention are typically encoded on some form of program storage medium or implemented over some type of transmission medium. The program storage medium may be magnetic (e.g., a floppy disk or a hard drive) or optical (e.g., a compact disk read only memory, or “CD ROM”), and may be read only or random access. Similarly, the transmission medium may be twisted wire pairs, coaxial cable, optical fiber, or some other suitable transmission medium known to the art. The invention is not limited by these aspects of any given implementation.

Thus, in various aspects and embodiments, the technique disclosed herein offers a number of benefits and advantages relative to conventional practice. The benefits and advantages may include:

-   -   more efficient acquisition of marine seismic data, wherein         “efficiency” may be considered as more cost effective in that         less seismic resources are used,     -   improved seismic imaging using minimal marine seismic equipment;     -   some embodiments may employ only one vessel, although an         additional source vessel may be used in other embodiments as         will be explained more fully below;     -   a richer azimuth survey can be acquired, i.e., a survey rich         azimuth and offset distribution;     -   reduced redundancy in azimuth in the acquired data since         azimuths are different from shot to shot;     -   a line change on the order of only a few minutes is required         only for data management reasons, otherwise the survey may be         acquired continuously;     -   the number of shots acquired over the survey is larger than the         number of shots acquired over the same survey by a parallel         design and, depending on the design of the acquisition, the         ratio could be between 1.5 to 2 times more shots for sincurve         acquisition versus parallel wide-azimuth or parallel         rich-azimuth acquisition—the large number of shots translates         into high fold and consequently an improved signal-to-noise         ratio of the seismic data;     -   less sensitivity to currents;     -   better near offset distribution is acquired for sincurve         acquisition method than for parallel acquisition;     -   for sincurve shooting the same offset range is acquired for         every azimuth whereas, for parallel geometries, offset         distribution is not the same for every azimuth, larger offsets         being acquired in the inline direction than in the crossline         direction;     -   full-azimuth sincurve acquisition makes possible to conduct         fracture characterization studies and geomechanical studies         based on P-waves amplitude and velocity variations with the         azimuth;     -   the high signal-to-noise ratio that could be obtained with         sincurve acquisition could be also beneficial for prospecting         deep targets or targets that are below strong reflectors, like         basalt or carbonate layers     -   no infill, or at least a minimum amount of infill;     -   less sensitivity to seismic interferences;     -   the effect of perturbations due to the obstructions may be less         than for multiple-vessel, linear wide-azimuth acquisition; and     -   pseudo-random distribution of the source points; this could be         beneficial for 3D multiple attenuation and imaging     -   the technical downtime associated with sincurve acquisition         could be less than for a multiple-vessel wide-azimuth         acquisition due to the use of a single vessel only;     -   improved reservoir illumination (including, but not limited to,         sub-salt reservoir illumination) and more effective coherent         noise attenuation due to the high variability of azimuths.         Other benefits and advantages may become apparent to those         skilled in the art having the benefit of this disclosure. Note         that not all embodiments or aspects of the present technique         will necessarily manifest or yield all of these benefits         advantages.

The following documents are incorporated by reference herein for all purposes as if set forth herein verbatim:

-   -   U.S. Provisional Application Ser. No. 60/938,547 filed May 17,         2007, entitled, “Methods for Efficiently Acquiring Wide-Azimuth         Towed Streamer Seismic Data”, and filed in the name of the         inventors Nicolae Moldoveanu and Steven Fealy.     -   U.S. Provisional Application Ser. No. 60/966,534 (converted from         U.S. application Ser. No. 11/836,675, filed Aug. 9, 2007, by         petition filed Aug. 31, 2007), entitled, “Methods for         Efficiently Acquiring Wide-Azimuth Towed Streamer Seismic Data”,         and filed in the name of the inventors Nicolae Moldoveanu and         Steven Fealy.     -   U.S. Provisional Application Ser. No. 60/969,203 filed Aug. 31,         2007, entitled, “Methods for Efficiently Acquiring Wide-Azimuth         Towed Streamer Seismic Data”, and filed in the name of the         inventors Nicolae Moldoveanu and Steven Fealy.     -   U.S. application Ser. No. 11/836,675, filed Aug. 9, 2007,         entitled, “Methods for Efficiently Acquiring Wide-Azimuth Towed         Streamer Seismic Data”, and filed in the name of the inventors         Nicolae Moldoveanu and Steven Fealy, which was converted to U.S.         Provisional Application Ser. No. 60/966,534 by petition filed         Aug. 31, 2007;     -   U.S. application Ser. No. 11/114,773, filed Apr. 26, 2005,         entitled, “Seismic Streamer System and Method”, and filed in the         name of the inventors Rohitashva Singh, et al., published Oct.         26, 2006, as Patent Publication 20060239117 A1;     -   U.S. application Ser. No. 11/122,646, filed Mar. 5, 2005,         entitled, “Forward looking systems and methods for positioning         marine seismic equipment”, and filed in the name of the         inventors Ruen Toennessen, et al., published Nov. 16, 2006, as         Patent Publication 20060256653 A1;     -   U.S. Pat. No. 5,668,775, entitled “Methods for determining the         position of seismic equipment, and applications of the methods”,         and issued Sep. 16, 1997, to GECO A.S. in the name of the         inventor Kjell Hatteland;     -   U.S. Pat. No. 6,671,223, entitled “Control devices for         controlling the position of a marine seismic streamer”, and         issued Dec. 30, 2003, to WesternGeco, L.L.C. in the name of the         inventor Simon H. Bittleston;     -   U.S. Pat. No. 3,774,570, entitled “Non-Rotating Depth Controller         Paravane for Seismic Cables”, and issued Nov. 27, 1973, to         Whitehall Electronics in the name of the inventors Raymond H.         Pearson;     -   U.S. Pat. No. 3,560,912, entitled “Control System for a Towed         Vehicle”, and issued Feb. 2, 1971, to Westinghouse Electric         Corporation in the name of the inventors P. G. Spink, et al.;     -   U.S. Pat. No. 5,443,027, entitled “Lateral force device for         underwater towed array”, and issued Aug. 22, 1995, to The United         States of America as represented by the Secretary of the Navy in         the name of the inventors Norman L. Owsley;     -   U.S. Pat. No. 3,605,674, entitled “Underwater Cable Controller”,         and issued Sep. 20, 1971, to Dresser Industries, Inc. in the         name of the inventor Raymond C. Weese;     -   U.S. Pat. No. 4,404,664, entitled “System for laterally         positioning a towed marine cable and method of using same”, and         issued Sep. 13, 1983, to Mobil Oil Corporation in the name of         the inventor Robert G. Zachariadis;     -   U.S. Pat. No. 6,525,992, entitled “Devices for controlling the         position of an underwater cable”, and issued Feb. 25, 2003, to         Input/Output, Inc. in the name of the inventors Andrew W.         Olivier, et al.; and     -   EP Patent Publication No. EP 0613025, entitled “A Device and         Method for Positioning of Towing Systems for Use in Marine         Seismic Systems”, and filed Feb. 22, 1994, in the name of the         inventor Tor Elholm.

The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the invention. Accordingly, the protection sought herein is as set forth in the claims below. 

What is claimed is:
 1. A method for designing a survey, comprising: identifying a desired region; and determining, using a processor, a plurality of generally curved advancing sail paths of a marine seismic spread over the desired region, wherein: the marine seismic spread comprises a plurality of marine seismic streamers; and respective generally curved advancing sail paths in the plurality of generally curved advancing sail paths have a radius that is a function of a width of the marine seismic spread.
 2. The method of claim 1, wherein the respective generally curved advancing sail paths are functions of a roll in a y-direction (“DY”) and a roll in an x-direction (“DX”).
 3. The method of claim 2, wherein DX and DY are functions of the width of the marine seismic spread.
 4. The method of claim 2, wherein DX and DY range from about 0.5 times to about 2 times the width of the marine seismic spread.
 5. The method of claim 2, wherein DX and DY are functions of the width of the marine seismic spread and the desired coverage fold for the desired region.
 6. The method of claim 2, wherein DX and DY are substantially equal.
 7. The method of claim 1, wherein none of the generally curved advancing sail paths is repeated.
 8. The method of claim 1, wherein a source is towed by a first vessel and the marine seismic streamers are towed by a second vessel different from the first vessel.
 9. The method of claim 1, wherein a source and the marine seismic streamers are towed by one vessel.
 10. The method of claim 1, wherein the survey is configured to acquire full azimuth seismic data of the desired region.
 11. The method of claim 1, wherein each generally curved advancing path is a generally oval path, a generally elliptical path, a figure-eight path, a generally sincurve path, or some combination thereof.
 12. The method of claim 1, wherein the generally curved advancing paths comprise at least one non circular path.
 13. A method for a survey design, comprising: identifying a desired region; and determining, using a processor, a plurality of generally curved advancing sail paths of a marine seismic spread, wherein: the marine seismic spread comprises a plurality of marine seismic streamers; and respective generally curved advancing sail paths in the plurality of generally curved advancing sail paths have a radius that is a function of a desired coverage fold for the desired region.
 14. The method of claim 13, wherein the radius is a function of a width of the marine seismic spread, or a combination of the width of the marine seismic spread and the desired coverage fold.
 15. The method of claim 13, wherein the desired region is to be substantially covered by the plurality of generally curved advancing sail paths during the survey.
 16. The method of claim 13, wherein the desired region comprises a sub-sea geologic region.
 17. A method for a marine seismic acquisition, comprising: towing a marine seismic spread in a generally curved advancing path over a survey area to form a plurality of generally circular sail paths, wherein: the marine seismic spread includes a source and a plurality of marine seismic streamers, and respective generally circular sail paths in the plurality of generally circular sail paths have a radius that is a function of a width of the marine seismic spread; shooting the source while towing the marine seismic spread in the generally curved advancing path; and recording a plurality of reflections from the survey area.
 18. The method of claim 17, wherein the survey area comprises a sub-sea geologic region of interest.
 19. The method of claim 18, wherein the reflections from the survey area provide a full azimuth survey of the sub-sea geologic region of interest.
 20. The method of claim 17, wherein the reflections from the survey area provide a full azimuth survey of at least a portion of the survey area.
 21. The method of claim 17, further comprising moving the marine seismic spread in a y-direction (DY) and a roll in an x-direction (DX) while towing the marine seismic spread in the generally curved advancing path.
 22. The method of claim 21, wherein the respective generally circular sail paths are functions of DX and DY.
 23. The method of claim 21, wherein DX and DY are functions of the width of the marine seismic spread.
 24. The method of claim 21, wherein DX and DY are functions of the width of the marine seismic spread and the desired coverage fold for the survey area.
 25. The method of claim 17, wherein none of the generally circular sail paths is repeated.
 26. The method of claim 17, wherein the source is towed by a first vessel and the marine seismic streamers are towed by a second vessel different from the first vessel.
 27. The method of claim 17, wherein the source and the marine seismic streamers are towed by one vessel.
 28. The method of claim 17, wherein shooting the source while towing the marine seismic spread comprises substantially continuously shooting the source until the survey area is substantially covered by the generally circular sail paths.
 29. The method of claim 17, further comprising actively steering the marine seismic streamers through the generally curved advancing path.
 30. A method for a marine seismic acquisition, comprising: towing a marine seismic spread in a generally curved advancing path over a survey area to form a plurality of generally circular sail paths, wherein: the marine seismic spread includes a source and a plurality of marine seismic streamers, and respective generally circular sail paths in the plurality of generally circular sail paths have a radius that is a function of a desired coverage fold for the survey area; shooting the source while towing the marine seismic spread in the generally curved advancing path; and recording a plurality of reflections from the survey area.
 31. The method of claim 30, wherein the radius is a function of a width of the marine seismic spread, or a combination of the width of the marine seismic spread and the desired coverage fold.
 32. The method of claim 30, further comprising actively steering the marine seismic streamers through the generally curved advancing path.
 33. The method of claim 32, wherein actively steering the marine seismic streamers comprises controlling a plurality of streamer steering devices coupled to the marine seismic streamers.
 34. An apparatus, comprising: a tow vessel; an array of marine seismic streamers coupled to the tow vessel, each streamer including: a seismic cable, a plurality of receivers disposed on the seismic cable along the length thereof, and a plurality of steering devices; a first computing apparatus programmed to sail the tow vessel in a generally curved advancing path over a survey area to form a plurality of generally circular sail paths, respective generally circular sail paths having a radius that is a function of a width of the array of marine seismic streamers; and a second computing apparatus programmed to actively steer at least one marine seismic streamer in the array of marine seismic streamers through the generally curved advancing path.
 35. The apparatus of claim 34, further comprising a source and a third computing apparatus programmed to shoot the source while the marine seismic streamers are towed in the generally curved advancing path.
 36. The apparatus of claim 35, wherein the first computing apparatus is the third computing apparatus.
 37. The apparatus of claim 35, wherein the first computing apparatus comprises the second computing apparatus and the third computing apparatus.
 38. The apparatus of claim 34, wherein the first computing apparatus is the second computing apparatus.
 39. The apparatus of claim 34, wherein the generally curved advancing path includes advances in a y-direction (“DY”) and a roll in an x-direction (“DX”).
 40. The apparatus of claim 34, wherein the generally curved advancing path is a generally oval advancing path, a generally elliptical advancing path, a figure-eight path, a generally sincurve advancing path, or some combination thereof.
 41. The apparatus of claim 34, wherein the radius is a function of a desired coverage fold for the survey area, or a combination of the width of the marine seismic spread and the desired coverage fold.
 42. A method for a survey design, comprising: identifying a desired region; and determining, using a processor, a plurality of generally curved advancing sail paths of a marine seismic spread, wherein: the marine seismic spread comprises a plurality of marine seismic streamers; and the plurality of generally curved advancing sail paths vary throughout a survey.
 43. A method for designing a survey, comprising: identifying a desired region; and determining, using a processor, a plurality of generally curved advancing sail paths of a marine seismic spread over the desired region, wherein: the marine seismic spread comprises a plurality of marine seismic streamers; respective generally curved advancing sail paths in the plurality of generally curved advancing sail paths have a radius that is a function of a width of the marine seismic spread; the respective generally curved advancing sail paths are a function of a roll in a y-direction (“DY”) and a roll in an x-direction (“DX”); and the survey is configured to acquire full azimuth seismic data of the desired region. 